The present invention relates to enhancing fluid flow from subterranean formations, and more particularly, to enhancing the conductivity of fractures in a subterranean formation so as to enhance fluid flow therethrough.
Hydraulic fracturing is a technique for stimulating the production of desirable fluids from a subterranean formation. The technique normally involves introducing a viscous liquid through a well bore into a formation at a chosen rate and pressure to enhance and/or create a fracture in a portion of the formation, and placing proppant particulates in the resultant fracture to, inter alia, maintain the fracture in a propped condition when the pressure is released. The resultant propped fracture provides a conductive channel in the formation for fluids to flow to the well bore.
The degree of stimulation afforded by the hydraulic fracturing treatment is largely dependent on the conductivity and width of the propped fracture. Thus, the productivity of the well in effect becomes a function of fracture conductivity, which is commonly defined as proppant permeability times fracture width. To enhance well productivity, it may be beneficial to enhance fracture conductivity.
Oftentimes, to effectively prop open the fractures as well as prevent proppant particulate flowback, the proppant particulates are caused or allowed to consolidate into proppant matrixes within the fractures. One conventional means of doing this is to use resin-coated proppant particulates so that when the resin cures downhole, the proppant particulates can consolidate to form a relatively stable proppant matrix within the fracture. Other methods also have been used to facilitate the consolidation of the proppant particulates within the fractures.
Although consolidating the proppant particulates within a fracture may have some benefits, for example preventing proppant flowback, such methods may adversely affect the conductivity of the fracture. That is, some methods of consolidating proppant particulates themselves may introduce a barrier to the free flow of desirable fluids from the subterranean formation to the well bore for subsequent production. Fracture conductivity may suffer as a result. This is undesirable as this may affect overall well productivity.
To counteract this potential problem, many different techniques have been developed. One technique involves adding calcium carbonate or salt to the proppant matrix composition. When the proppant particulates consolidate, after a subsequent fluid is added to the well bore, the calcium carbonate or salt is dissolved out of the matrix. At least one problem associated with this method is the incomplete removal of the calcium carbonate or salt if not adequately contacted with the subsequent fluid. Another method has been to add wax beads to the proppant matrix composition. Once incorporated into the consolidated proppant particulates, the wax beads melt as a result of the temperature of the formation. A problem with this method is that the wax may re-solidify in the well, causing countless problems. Another method that has been used is to add an oil-soluble resin to the proppant matrix composition; however, this method has not been successful because of, inter alia, nonuniform removal of the particles.
Another way to address fracture conductivity has been to use bigger proppant particulates. However, there are practical limits to the size of the proppant particulates that may be used. For instance, if the particles used are too large, premature screenout at the perforations and/or fractures during the proppant stage of fracturing treatment often occurs as a large amount of proppant particulates is being injected into the fractures. In addition, by using proppant particulates that are too large, the ability to control formation sand is lost as the formation sand or fines tend to invade or penetrate the large pore space of the proppant matrix during production of hydrocarbons, thus potentially choking the flow paths of the fluids.